Analytical testing for contaminants in a petroleum fluid is an important step in many industrial processes. Contaminants can be in the form of small amounts of other types of fuels which have remained, for example, in multi-purpose pipelines or refined oil storage tanks. Contaminants can be in the form of small amounts of the same fuel but having different sulfur contents, which commonly happens in diesel fuel distribution operations and storage. The contaminants can also be in the form of weathered fuels mixed with fresh ones or in the form of some chemicals that cannot readily be identified.
Water as a contaminant is a concern in certain applications. The contamination of jet fuel by condensation water is known to be a serious safety concern in the aviation industry and was found to be the cause of several helicopter crashes in hot and humid tropical countries.
Common analytical methods of testing for contaminants include using infrared absorption, ultra violet (UV) absorption, and nuclear magnetic resonance, but each of these contain drawbacks.
Liquid hydrocarbon fuels (e.g., jet fuel, gasoline, and diesel fuel) can be characterized by fluorescence emission spectra of distinct shapes when excited with ultraviolet light. When such fuels become contaminated or blended with another type of fuel their spectral shapes suffer alterations depending on the fluorescence spectral/temporal characteristics of the contaminants. In most of these cases, the contaminants in the hydrocarbon fuels can be identified by making a comparison in the shapes of the fluorescence emission spectra between the contaminated and the uncontaminated samples. In one method the identification of the oil is made by direct visual comparison of the sample's fluorescence emission spectrum with the same spectra of possible source samples, all being excited using ultraviolet radiation at 254 nm. In other words, to perform spectral comparisons, whether visual or numerical, measurements must first be performed on a reference sample, or on a set of reference samples, in order to generate the necessary reference data to which the measurements from the unknown sample will be compared. In many cases, the needed information will not be only the type of the contaminants but also their volume ratios in the blend, i.e., their concentrations. This, in turn, necessitates the additional steps of preparing sets of standard blends with known concentrations and performing measurements on them to produce the necessary calibration curves.
A more difficult contaminant to quantify or even to identify is water. Water does not fluoresce. Known fluorescence-based methods are primarily adapted for measurement of oil-in-water emulsions, for the range of volumetric water concentrations from approximately 50% up to 99%. These methods are not well-adapted for the different design parameters facing water-in-oil measurement for water concentrations in the range from 0.01% up to a few percent by volume, because water does not fluoresce, the prominent fluorescence signal from the oil will not be appreciably affected by the presence of only minute amounts of water. The inability to accurately measure low concentrations of water in oil means there is no good way of measuring water concentration locally inside a water-in-oil emulsion flow domain. Consequently, there is almost no experimental data on water concentration gradients inside flowing emulsion layers available to the scientific community. Such data would be useful to better understand the behavior of flowing emulsions and the development of models describing the formation and separation of flowing emulsions.
In addition, none of the methods known in the prior art describe a direct correlation between laser-induced fluorescence intensity measurements of oil in a water-in-oil mixture and the water content in the mixture.
The main techniques for accurate water concentration measurement in the volumetric range between 0.01% and about 1% are based on the titration of a chemical reactant (e.g., I2 reacts quantitatively with H2O present in the oil). This and other techniques involving sampling, dilution, and several successive manipulations in a laboratory environment make them impractical for real-time process monitoring applications as needed in crude oil production facilities as well as in oil refineries and petrochemical plants, because they are intrusive to flowing fluids. For example, one method known in the prior art assesses a multiphase mixture sample including an aqueous phase by using a fluorescing dye. The addition of a detection molecule in the fluorescing dye, which fluoresces on contact with the particular phase to be assessed, is intrusive to the flow by requiring the dye to be added to the flow in order to measure water in oil samples. These methods are also ill suited to measuring local water content in a tank or other holding device.
Therefore, a need exists for an apparatus capable of determining trace amounts of water in oil that can be submerged at different depths in a fuel storage tank to detect water contamination and measure water concentration at different heights, that can be installed in-line with the process stream at a suitable location in the process or installed on a by-pass line, that is a non-intrusive method of measuring water concentration in a fluid having a low water content, and a method and system capable of rapidly and non-intrusively detecting trace amounts of water in localized regions within a volume of oil-containing fluid.